Real-time Form 4 intelligence. Smarter insider tracking.
YoY shift: Lean +
Year-over-year tone shift - average net-tone change across Risk Factors and MD&A vs the prior 10-K. This filing is 0.18pp more bullish than last year's.
Why YoY instead of absolute: the LM lexicon has ~6.6× more negative words than positive (legal/risk-disclosure language is heavy on hedging), so every 10-K reads bearish on raw tone. Year-over-year change strips that bias and surfaces the actual shift in management's framing.
Tone shift by section
The two components the gauge averages: how Risk Factors and MD&A each shifted in net tone versus last year's 10-K. The headline above is their average, so a green needle over a soft section just means the other section carried it.
Risk Factors
+0.00pp
Flat
Net-tone change vs last year's 10-K.
MD&A
+0.37pp
Lean +
Net-tone change vs last year's 10-K.
Per-snippet highlights
Sentence-level sentiment highlighting with category and subcategory filters is coming once the snippet-scoring pipeline lands. For now, dig into the actual section text on the Sections tab.
Language change vs prior 10-K
Risk Factors (Item 1A) - words with the biggest YoY frequency increase
Negative rising
damage+2
delay+1
stringent+1
destruction+1
lack+1
Positive rising
successfully+1
successful+1
advantage+1
profitable+1
Risk Factors (Item 1A)
16,340 words
Item 1A. Risk Factors.
Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, financial condition, or results of operations could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect us.
Risks Related to Commodity Prices
Declines in crude oil, natural gas, and NGL prices will adversely affect our business, financial condition or results of operations, and our ability to meet our capital expenditure obligations or targets and financial commitments.
The price we receive for our crude oil, natural gas, and NGL heavily influences our revenue, profitability, cash flows, liquidity, access to capital, present value and quality of our reserves, and the nature and scale of our operations. Crude oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. In recent years, the markets for crude oil and natural gas have been volatile. These markets will likely continue to be in the future. Further, crude oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other.
Language change vs prior 10-K
MD&A (Item 7) - words with the biggest YoY frequency increase
Negative rising
declining+2
volatility+1
slowdown+1
oversupply+1
negative+1
Positive rising
gain+5
rebounded+2
greater+2
premier+1
rebound+1
MD&A (Item 7)
8,496 words
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis contains forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions, and resources. Such forward-looking statements should be read in conjunction with our disclosures under “ Part I - Item 1A. Risk Factors ” of this Form 10-K. Additionally, due to the combination of different units of volumetric measure, the number of decimal places presented and rounding, certain results may not calculate explicitly from the values presented in the tables.
This section of this Form 10-K generally discusses 2024 and 2023 results and year-to-year comparisons between 2024 and 2023. Discussions of 2022 items and year-to-year comparisons between 2023 and 2022 that are not included in this Form 10-K can be found in “ Part II - Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations ” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2023.
Executive Summary
We are an independent exploration and production company focused on the acquisition, development, and production of crude oil and associated liquids-rich natural gas from our premier assets in the DJ Basin in Colorado and the Permian Basin in Texas and New Mexico. Our proven business model to maximize stockholder returns is focused on four key strategic pillars: generate significant free cash flow, maintain a balance sheet, return capital to our stockholders, and demonstrate ESG .
During times of suppressed crude oil prices, we have historically experienced significant decreases in crude oil revenues and recorded unproved property asset impairment charges. Any prolonged period of low market prices for crude oil, natural gas, and NGL could result in future capital expenditures being reduced and will necessarily adversely affect our business, financial condition, and liquidity and our ability to meet obligations, targets, or financial commitments. During the year ended December 31, 2024, the daily NYMEX WTI crude oil spot price ranged from a high of $86.91 per Bbl to a low of $65.75 per Bbl, and the NYMEX HH natural gas spot price ranged from a high of $13.20 per MMBtu to a low of $1.21 per MMBtu. As of February 21, 2025, the daily NYMEX WTI crude oil spot price and NYMEX HH natural gas spot price was $70.40 per Bbl and $4.23 per MMBtu, respectively.
The prices we receive for our production and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
• worldwide, regional, and local economic conditions impacting the global supply and demand for crude oil and natural gas;
• the actions from members of the Organization of Petroleum Exporting Countries and other crude oil producing nations;
• the price and quantity of imports of foreign crude oil and natural gas;
• political conditions in or affecting other crude oil and natural gas producing countries, including the current conflicts in the Middle East and involving Russia and Ukraine and conditions in South America;
• the level of domestic and global crude oil and natural gas exploration and production;
• the level of domestic and global crude oil and natural gas inventories;
• localized supply and demand fundamentals and transportation availability;
• weather conditions and natural disasters, including the physical effects of climate change;
• local, domestic, and foreign governmental regulations and policies, including regulations addressing climate change and trade policies, including tariffs;
• speculation as to the future price of crude oil and the speculative trading of crude oil and natural gas futures contracts;
• the price and availability of competitors’ supplies of crude oil and natural gas;
• technological advances affecting energy consumption;
• variability in subsurface reservoir characteristics, particularly in areas with immature development history, even within areas in close proximity within the same basin or field;
• the availability of pipeline capacity and infrastructure; and
• the price and availability of alternative fuels.
Substantially all of our production is sold to purchasers under contracts at market-based prices. Declines in commodity prices may have the following effects on our business:
• reduction of our revenues, profit margins, operating income, and cash flows;
• reduction in the amount of crude oil, natural gas, and NGL that we can produce economically, and reduction in our liquidity and inability to pay our liabilities as they come due;
• certain properties in our portfolio becoming economically unviable;
• delay or postponement of some of our capital projects;
• significant reductions in future capital programs, resulting in a reduced ability to develop our reserves;
• limitations on our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations;
• reduction to the borrowing base under our Credit Facility or limitations in our access to sources of capital, such as equity or debt;
• declines in our stock price;
• reduction in industry demand for crude oil;
• reduction in storage availability for crude oil;
• reduction in pipeline and processing industry demand and capacity for natural gas;
• reduction in the ability of our vendors, suppliers, and customers to continue operations due to the prevailing adverse market conditions; and
• asset impairment charges resulting from reductions in the carrying values of our crude oil and natural gas properties at the date of assessment.
If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we may be required to take write-downs of the carrying values of our properties.
We review our proved crude oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics, and other factors, from time to time, we may be required to write-down the carrying value of our crude oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. Given the historical price volatility in the crude oil and natural gas markets, prices may decline or other events may arise that would require us to record further impairments of the book values associated with crude oil and natural gas properties. Accordingly, we may incur significant impairment charges in the future, which could have a material adverse effect on our results of operations and could reduce our earnings and stockholders’ equity for the periods in which such charges are taken.
Risks Related to Our Reserves, Leases, and Drilling Locations
Our estimated proved reserves and our ultimate number of prospective well development locations are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating crude oil and natural gas reserves and the production possible from our oil and gas wells is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. See “ Item 1. Business - Estimated Proved Reserves ” of this Annual Report on Form 10-K for information about our estimated crude oil and natural gas reserves and the PV-10 (a non-GAAP financial measure) as of December 31, 2024, 2023, and 2022.
In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production, and engineering data. The extent, quality, and reliability of this data can vary. The process also requires economic assumptions about matters such as crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds, and given the current volatility in pricing, such assumptions are difficult to make. Although the reserves information contained herein is audited or prepared by independent reserves engineers, estimates of crude oil and natural gas reserves are inherently imprecise, particularly as they relate to state-of-the-art technologies being employed, such as the combination of hydraulic fracturing and horizontal drilling.
Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating expenses, and quantities of recoverable crude oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K and cause potential impairment charges. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing crude oil and natural gas prices, and other factors, many of which are beyond our control.
The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated crude oil and natural gas reserves.
You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated crude oil and natural gas reserves. In accordance with SEC requirements for the years ended December 31, 2024, 2023, and 2022, we based the estimated discounted future net revenues from our proved reserves on the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months (after adjustment for location and quality differentials), without giving effect to derivative transactions. Actual future net revenues from our crude oil and natural gas properties will be affected by factors such as:
• actual prices we receive for crude oil and natural gas and hedging instruments;
• actual cost of development and production activities;
• the amount and timing of actual production;
• the amount and timing of future development costs;
• wellbore productivity realizations above or below type curve forecast models;
• the supply and demand of crude oil and natural gas; and
• changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor (the factor required by the SEC) used when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the crude oil and natural gas industry in general.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.
The development of our proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate or that may be available to us. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.
Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. Our ability to drill and develop these locations is subject to a number of uncertainties, including uncertainty in the level of reserves; the availability of capital to us and other participants; seasonal conditions; regulatory approvals; activist intervention; crude oil, natural gas, and NGL prices; availability of permits; costs; and well performance. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations. Pursuant to existing SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking, and we may therefore be required to downgrade to probable or possible categories any proved undeveloped reserves that are not developed within this five-year time frame. These limitations may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.
Drilling locations that we decide to drill may not yield crude oil or natural gas in commercially viable quantities.
We describe some of our drilling locations and our plans to explore those drilling locations in this Annual Report on Form 10-K. Our drilling locations are in various stages of evaluation, ranging from a location that is ready to drill to a location that will require substantial additional evaluation. There is no way to predict in advance of drilling and testing whether any particular location will yield crude oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. Prior to drilling, the use of 2-D and 3-D seismic technologies, various other technologies, and the study of producing fields in the same area will still not enable us to know conclusively whether crude oil or natural gas will be present or, if present, whether crude oil or natural gas will be present in sufficient quantities to be economically viable. In addition, the use of 2-D and 3-D seismic data and other technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures which may result in a reduction in our returns or increase our losses. Even if sufficient amounts of crude oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. If we drill any dry holes in our current and future drilling locations, our profitability and the value of our properties will likely be reduced. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations, or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators may not be indicative of future or long-term production rates. In sum, the cost of drilling, completing, and operating any well is often uncertain, and new wells may not be productive.
Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.
The terms of our oil and gas leases often stipulate that the lease will terminate if not held by production, rentals, or otherwise some form of an extension payment to extend the term of the lease. As of December 31, 2024, approximately 17,600 net acres of our properties were not held by production. For these properties, if production in paying quantities is not established on units containing leases during the next year, then approximately 7,800 net acres will expire in 2025, approximately 5,400 net acres will expire in 2026, and approximately 4,400 net acres will expire in 2027 and thereafter. While some expiring leases may contain predetermined extension payments, other expiring leases will require us to negotiate new leases at the time of lease expiration. Further, existing leases which are currently held by production may unexpectedly encounter operational, political, regulatory, or litigationchallenges which could result in their termination. It is possible that market conditions at the time of negotiation could require us to agree to new leases on less favorable terms to us than the terms of the expired leases or cause us to lose the leases entirely. If our leases expire, we will lose our right to develop the related properties.
Unless we replace our crude oil and natural gas reserves, our reserves and production will decline, which could adversely affect our business, financial condition, and results of operations.
In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our current proved reserves will decline as reserves are produced and, therefore, our level of production and cash flows will be affected adversely unless we conduct successful exploration and development activities or acquire properties containing proved reserves. Thus, our future crude oil and natural gas production and, therefore, our cash flow and income are highly dependent upon our level of success in finding, acquiring, and/or developing additional reserves. However, we cannot assure you that our future acquisition, development, and exploration activities will result in any specific amount of additional proved reserves or that we will be able to drill productive wells at acceptable costs.
Risks Related to Our Business and Operations
Drilling for and producing crude oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition, or results of operations.
Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development, and production activities. Our crude oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable crude oil or natural gas production. Our decisions to purchase, lease, explore, develop, or otherwise exploit drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “Risks Related to Our Reserves, Leases, and Drilling Locations - Our estimated proved reserves and our ultimate number of prospective well development locations are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves ” above. Our cost of drilling, completing, and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors, including, but not limited to, the following, may result in substantial losses, including personal injury or loss of life, penalties, damage or destruction of property and equipment, and curtailments, delays, or cancellations of our scheduled drilling, completion, and infrastructure projects:
• shortages of or delays in obtaining equipment and qualified personnel;
• facility or equipment malfunctions;
• unexpected operational events;
• unanticipated environmental liabilities;
• pressure or irregularities in geological formations;
• adverse weather conditions, such as extreme cold temperatures, blizzards, ice storms, tornadoes, floods, and fires;
• reductions in crude oil and natural gas prices;
• delays imposed by or resulting from compliance with regulatory requirements, such as permitting delays;
• proximity to and capacity of transportation facilities;
• access to and availability of reliable sources of electric power;
• title issues or inaccuracies;
• safety and/or environmental conditions; and
• limitations in the market for crude oil and natural gas.
Imbalances between the supply and demand for crude oil and natural gas could result in transportation and storage constraints, reductions of our planned production, and related shut-in of our wells, which could adversely affect our business, financial condition, and results of operations.
Any future excess supply of crude oil and natural gas could impact our ability to sell our production because of transportation or storage constraints, causing us to shut-in or curtail production or flare our natural gas. Any such prolongedshut-in of our wells may result in decreased well productivity once we are able to resume operations, and any cessation of drilling and development of our acreage could result in the expiration, in whole or in part, of our leases. The occurrence of any of these risks may, in the future, adversely affect our business, financial condition, and results of operations.
We intend to pursue the further development of our properties through horizontal drilling and completion, which can be operationally challenging and costly.
Horizontal drilling can be complex and expensive. Risks associated with our horizontal drilling program include, but are not limited to, the following, any of which could materially and adversely impact the success of our horizontal drilling program and, thus, our cash flows and results of operations:
• successfully drilling and maintaining the wellbore to planned total depth;
• landing our wellbore in the desired hydrocarbon reservoir;
• effectively controlling the level of pressure flowing from particular wells;
• staying in the desired hydrocarbon reservoir while drilling horizontally through the formation;
• running our casing through the entire length of the wellbore;
• running tools and other equipment consistently through the horizontal wellbore;
• successful design and execution of the fracture stimulation process;
• preventing downhole communications with other wells, or, in the alternative, disruption from non-simultaneous operations;
• successfully cleaning out the wellbore after completion of the final fracture stimulation stage; and
• designing and maintaining efficient forms of artificial lift throughout the life of the well.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, limited takeaway capacity, or depressed crude oil and natural gas prices, the return on our investment in these areas may not be as attractive as anticipated. Further, as a result of any of these developments, we could incur material impairments of our oil and gas properties and the value of our undeveloped acreage could decline in the future.
We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues.
We do not operate all of the properties in which we have an interest. We own significant non-operated working interests which are not currently within our operated development plan. As a result, we may have a limited ability to exercise influence over normal operating procedures, expenditures, timing, or future development of underlying properties, and their associated costs. For all of the properties that are operated by others, we are dependent on their decision-making with respect to day-to-day operations over which we have little control. The failure of an operator of wells in which we have an interest to adequately perform operations, or an operator’s breach of applicable agreements, could reduce production and revenues we
receive from that well. The success and timing of our drilling and development activities on properties operated by others depend upon a number of factors outside of our control, including the timing and amount of capital expenditures, the available expertise and financial resources, the inclusion of other participants, and the use of technology. Our lack of control over non-operated properties also makes it more difficult for us to forecast capital expenditures, revenues, production, liability, and other related matters.
Our ability to sell crude oil, natural gas, and NGLs, and receive market prices for our production, may be adversely affected by constraints on gathering systems, processing facilities, pipelines, and other transportation systems owned or operated by third-parties or by other interruptions beyond our control, which could impact the marketability of our production.
The marketability of our crude oil, natural gas, and NGL production depends in part on the availability, proximity, and capacity of gathering systems, processing facilities, pipelines, and other transportation systems, which are generally owned or operated by third parties. Any significant interruption in service from, damage to, or lack of available capacity in these systems and facilities can result in the shutting-in of our producing wells, delay or discontinuance of development plans for our properties, increases in costs attributed to obtaining alternative takeaway capacity on less favorable terms, or lower price realizations. Additionally, federal and state regulation concerning the production and transportation of crude oil, natural gas, and NGLs, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines or processing facilities, infrastructure or capacity constraints, and our voluntary curtailment of production in response to market or other conditions could adversely affect our ability to produce, gather, process, transport, or market crude oil, natural gas, and NGLs. If a substantial amount of our production is interrupted at the same time, our business, results of operations, and financial condition may be materially adversely affected.
We may incur substantial losses and be subject to substantial liability claims as a result of our crude oil and natural gas operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks, including those related to our hydraulic fracturing operations.
Our crude oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing crude oil and natural gas, including, but not limited to, the possibility of:
• environmental hazards, such as spills, uncontrollable flows of crude oil, natural gas, brine, well fluids, natural gas, hazardous air pollutants, or other pollution into the environment, including soil, surface water, groundwater, and shoreline contamination;
• unpermitted releases of natural gas and hazardous air pollutants or other substances into the atmosphere at our oil and gas facilities;
• hazards resulting from the presence of hydrogen sulfide (H 2 S) or other contaminants in crude oil and natural gas we produce;
• abnormally pressured formations resulting in well blowouts, fires, or explosions;
• mechanical difficulties, such as stuck down-hole tools or casing collapse;
• cratering (catastrophicfailure);
• downhole communication leading to migration of contaminants;
• personal injuries and death; and
• natural disasters.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:
• injury or loss of life;
• damage to and destruction of property, natural resources, and equipment;
• pollution and other environmental and natural resource damages;
• regulatory investigations and penalties;
• suspension of our operations; and
• repair and remediation costs.
In addition, our operations in Colorado are susceptible to damage from natural disasters, such as flooding, wildfires, tornadoes, and other natural phenomena and weather conditions, including extreme temperatures, which involve increased risks of personal injury, property damage, and marketing interruptions. The occurrence of one of these operating hazards may result in injury, loss of life, suspension of operations, environmental damage and remediation liability, and/or governmental investigations and penalties. The payment of any of these liabilities could reduce, or even eliminate, the funds available for exploration and development, or could result in a loss of our properties.
As is customary in the oil and gas industry, we maintain insurance against some, but not all, of these potential risks and losses. Although we believe the coverage and amounts of insurance that we carry are consistent with industry practice, we do not have insurance protection against all risks that we face, because we choose not to insure certain risks, insurance is not available at a level that balances the costs of insurance and our desired rates of return, or actual losses exceed coverage limits. Insurance costs will likely continue to increase, which could result in our determination to decrease coverage and retain more risk to mitigate those cost increases. In addition, pollution and environmental risks generally are not fully insurable. If we incur substantial liability, and the damages are not covered by insurance or are in excess of policy limits, then our business, results of operations, and financial condition may be materially adversely affected.
Because hydraulic fracturing activities are integral to our operations, they are covered by our insurance againstclaims made for bodily injury, property damage, and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if the operator is unaware of the pollution event and unable to report the “occurrence” to the insurance company within the required time frame. We also do not have coverage for gradual, long-term pollution events, including climate change.
Under certain circumstances, we have agreed to indemnify third parties againstlosses resulting from our operations. Pursuant to our surface leases, we typically indemnify the surface owner for clean-up and remediation of the site. As owner and operator of oil and gas wells and associated gathering systems and pipelines, we typically indemnify the drilling contractor for pollution emanating from the well, while the contractor indemnifies us against pollution emanating from its equipment.
The oil and natural gas industry is highly competitive and many of our competitors have available resources in excess of our own.
The oil and natural gas industry is highly competitive. Many of our competitors, including major integrated and independent oil and natural gas companies, are larger and have substantially greater resources at their disposal than we do and may have a competitive advantage over us. For example, many oil and gas properties are sold in a competitive bidding process in which our competitors may be able and willing to pay more for exploratory and development prospects and productive properties, or in which our competitors have technological information or expertise that is not available to us to evaluate and successfully bid for properties. As a result, we may not be successful in acquiring and developing profitable properties.
In addition, other companies may have a greater ability to continue drilling activities during periods of low oil or gas prices and to absorb the burden of current and future governmental regulations and taxation, shortages of equipment, labor, or materials. As a result of this intense competition, we may incur increased costs or be unable to obtain the resources needed for our operations. If we are unable to effectively compete with our competitors, our business, results of operations, and financial condition may be materially adversely affected.
We may be unable to make attractive acquisitions, and any inability to do so may disrupt our business.
In the future, we may make acquisitions of producing properties or businesses that complement or expand our current business. The successful acquisition of producing properties requires an assessment of several factors, including:
• recoverable reserves;
• future crude oil, natural gas, and NGL prices and their applicable differentials;
• operating costs;
• location inventory; and
• potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain, and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is, where is” basis. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms or for other reasons stated herein.
Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms, or successfully acquire identified targets. In addition, our Credit Facility and the indentures governing our senior notes impose certain limitations on our ability to enter into mergers or combination transactions and also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions.
We may not realize anticipated benefits from mergers and acquisitions.
We seek to complete acquisitions in order to strengthen our position and to create the opportunity to realize certain benefits, including, among other things, potential cost savings and potential production multiples. Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner, as well as being able to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations. Acquisitions could also result in difficulties in being able to hire, train, or retain qualified personnel to manage and operate such properties.
Potential difficulties in realizing the anticipated benefits of mergers and acquisitions include:
• disruptions of relationships with customers, distributors, suppliers, vendors, landlords, joint venture partners, and other business partners as a result of uncertainty associated with such transactions;
• difficulties integrating our business with the acquired businesses in a manner that permits us to achieve the full revenue and cost savings from such transactions;
• complexities associated with managing a larger and more complex business, including difficulty addressing possible inconsistencies in, standards, controls, or operational philosophies and the challenge of integrating complex systems, technology, networks, and other assets of each of the companies in a seamless manner that minimizes any adverse impact on customers, suppliers, employees, and other constituencies;
• difficulties realizing operating synergies;
• difficulties integrating personnel, vendors, and business partners;
• loss of key employees;
• potential unknown inherited liabilities and unforeseen expenses;
• performance shortfalls at the companies as a result of the diversion of management’s attention to integration efforts; and
• disruption of, or the loss of momentum in, each company’s ongoing business.
Our future success will depend, in part, on our ability to manage our expanded business by, among other things, integrating the assets, operations, or personnel of acquired businesses in an efficient and timely manner; consolidating systems and management controls; and successfully integrating relationships with customers, vendors, and business partners. Failure to successfully manage the combined company may have an adverse effect on our business, reputation, financial condition, and results of operations.
We may be involved in legal cases that may result in substantial liabilities.
Like many oil and gas companies, we are involved in various legal and other cases, such as title, royalty, or contractual disputes, regulatory compliance matters, and personal injury or property damage matters, in the ordinary course of our business. Such legal cases are inherently uncertain, and their results cannot be predicted. Regardless of the outcome, such cases could have an adverse impact on us because of legal costs, diversion of management and other personnel, and other factors. In addition, it is possible that a resolution of one or more such cases could result in liability, penalties, or sanctions, as well as judgments, consent decrees, or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results, and financial condition. Accruals for such liability, penalties, or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other cases could change from one period to the next, and such changes could be material.
Terrorist attacks and armed conflict could have a material adverse effect on our business, financial condition, or results of operations.
Terrorist attacks and armed conflict may significantly affect the energy industry, including our operations and those of our current and potential customers, as well as general economic conditions, consumer confidence and spending, and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the U.S. Our insurance may not protect against such occurrences. Furthermore, commodity markets are currently also subject to heightened levels of uncertainty related to the Russian military invasion of Ukraine, which has given rise to regional instability and resulted in heightened economic sanctions by the U.S. and the international community that, in turn, could increase uncertainty with respect to global financial markets and production output from the Organization of Petroleum Exporting Countries and other crude oil producing nations. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, and results of operations.
We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption, or financial loss.
The oil and gas industry is highly dependent on digital technologies to conduct certain exploration, development, production, processing, and distribution activities. For example, we depend on digital technologies to interpret seismic data, manage drilling rigs, production equipment, and gathering and transportation systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. Pipelines, refineries, power stations, and distribution points for both fuels and electricity are increasingly more interconnected by computer systems. We also depend on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to process and record financial and operating data, communicate with our employees and business parties, analyze seismic and drilling information, estimate quantities of oil and gas reserves, as well as other activities related to our business. We also collect and store sensitive data in the ordinary course of our business, including personally identifiable information of our employees as well as our proprietary business information and that of our customers, suppliers, investors, and other stakeholders. Our business partners, including vendors, service providers, purchasers of our production, and financial institutions, are also dependent on digital technology. The secure processing, maintenance, and transmission of information is critical to our operations, and we monitor our key information technology systems in an effort to detect and prevent cyber-attacks, security breaches, or unauthorized access. At the same time, cyber incidents, including deliberate attacks or unintentional events, have continued to increase in frequency and are becoming increasingly sophisticated. Despite our security measures, our technologies, systems, networks, and those of our vendors, suppliers, and other business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, weaknesses in the cyber security of our vendors, suppliers, and other business partners could facilitate an attack on our technologies, systems, and networks. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Given the politically sensitive nature of hydraulic fracturing and the controversy generated by its opponents, our technologies, systems, and networks may be of particular interest to certain ideological groups, which may seek to launch cyber-attacks as a method of advancing their agenda. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient.
As cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber-attacks. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our personnel, information, facilities, and infrastructure may result in increased capital and operating costs. A cyber-attack or security breach could result in liability under data privacy laws, regulatory penalties, damage to our reputation, or loss of confidence in us, or additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences, all of which could have a material and adverse effect on our business, financial condition, or results of operations. To date we have not experienced any material losses relating to cyber-attacks; however, there can be no assurance
that we will not suffer such losses in the future. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, and results of operations.
Risks Related to Our Derivative Activities, Debt Agreements, and Access to Capital
Our production is not fully hedged, and we may hedge a lower percentage of our production than we have in the past. We are therefore exposed to fluctuations in the price of crude oil, natural gas, and NGL and will be affected by continuing and prolongeddeclines in such prices.
Crude oil, natural gas, and NGL prices are volatile. It is common within the industry to hedge a portion of crude oil and natural gas production to reduce a company’s exposure to adverse fluctuations in these prices. Within our company, we have stated limitations as prescribed in our reserve-based Credit Facility, as the borrower, with JPMorgan Chase Bank, N.A., as the administrative agent, and a syndicate of financial institutions as lenders (the “Credit Facility”) as to the percentage of our production that can be hedged. The limitations range from 85% to 100% of our projected production from our proved developed properties and 65% to 85% of our projected production from our total proved properties, dependent on the duration of the hedge. Due to the Credit Facility’s restrictions and/or management’s decision to hedge less than 100% of our projected production, some of our future production will be sold at market prices, exposing us to fluctuations in the price of crude oil and natural gas, which may have a material negative impact on our results of operations. See “ Part II - Item 8. Financial Statements and Supplementary Data - Note 9 - Derivatives ” of this Annual Report on Form 10-K for a summary of our hedging activity.
Our derivative activities could result in financial losses or could reduce our income.
To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of crude oil and natural gas, we have, and may in the future enter into additional, derivative arrangements for a portion of our crude oil, natural gas, and NGL production, including swaps, collars, and other instruments. We have not in the past designated any of our derivative instruments as hedges for accounting purposes and have recorded all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.
Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when:
• production is less than the volume covered by the derivative instruments;
• the counterparty to the derivative instrument defaults on its contract obligations; or
• there is an increase in the differential between the underlying price in the derivative instrument and actual prices received.
In addition, these types of derivative arrangements may limit the benefit we would receive from increases in the prices for crude oil and natural gas and may expose us to cash margin requirements.
We are exposed to credit risks of our hedging counterparties, third parties participating in our wells, and our customers.
Our principal exposures to credit risk are through receivables resulting from commodity price derivatives instruments, joint interest billings, and other components totaling $125.0 million as of December 31, 2024, and the sale of our crude oil, natural gas, and NGL totaling $646.3 million in receivables as of December 31, 2024, which we market to energy marketing companies, refineries, and affiliates.
Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We can do very little to choose who participates in our wells.
We are also subject to credit risk due to concentration of our crude oil, natural gas, and NGL receivables with significant customers. This concentration of customers may impact our overall credit risk since these entities may be similarly affected by changes in economic, political, and other conditions.
We are exposed to credit risk in the event of default of any of our counterparties, principally with respect to hedging agreements, but also with respect to insurance contracts and bank lending commitments. We do not require most of our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us.
The agreements covering our debt have restrictive covenants that could limit our ability to finance our operations, fund capital needs, respond to changing conditions, and engage in other business activities that may be in our best interests.
The agreements governing our debt, including the Credit Facility and the indentures governing our senior notes, contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our ability to borrow under the Credit Facility is subject to compliance with certain covenants, including the maintenance of certain financial ratios, including a minimum current ratio and a maximum leverage ratio. In addition, our debt agreements contain covenants that, among other things, limit our ability to:
• incur or guarantee additional indebtedness;
• issue preferred stock;
• sell or transfer assets;
• pay dividends on, redeem, or repurchase capital stock;
• repurchase or redeem subordinated debt;
• make certain acquisitions and investments;
• create or incur liens;
• engage in transactions with affiliates;
• enter into agreements that restrict distributions or other payments from restricted subsidiaries to us;
• consolidate, merge, or transfer all or substantially all of our assets; and
• engage in certain other business activities.
Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our indebtedness. We may not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness. As of the date of this Annual Report on Form 10-K, we were in compliance with all financial and non-financial covenants.
We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants contained in our debt documents. In addition, our ability to comply with the financial ratios and financial condition tests under the Credit Facility may be affected by events beyond our control and, as a result, we may be unable to meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a continued downturn in commodity prices, our business, or the economy in general, or otherwise conduct necessary corporate activities.
Borrowings under the Credit Facility are limited by our borrowing base, which is subject to periodic redetermination.
The borrowing base under the Credit Facility is redetermined at least semiannually and up to two additional times per year between scheduled determinations upon request of us or lenders holding more than 50% of the aggregate commitments. Redeterminations are based upon a number of factors, including commodity prices and reserve levels. In addition, our lenders have substantial flexibility to reduce our borrowing base due to subjective factors.
Upon a redetermination, we could be required to repay a portion of our bank debt to the extent our outstanding borrowings at such time exceed the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the facility and an acceleration of the loans thereunder requiring us to negotiate renewals, arrange new financing, or sell significant assets, all of which could have a material adverse effect on our business and financial results.
Our development and production projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our crude oil and natural gas reserves or anticipated sales volumes.
Our development and production activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production, and acquisition of crude oil and natural gas reserves. At this time, we intend to finance future capital expenditures primarily through cash flows provided by operating activities and borrowings under the Credit Facility. Declines in commodity prices coupled with our financing needs may require us to alter or increase our capitalization substantially through the issuance of additional equity securities or debt securities or the strategic sale of assets. The issuance of additional debt may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures, and acquisitions. In addition, upon the issuance of certain debt securities, our borrowing base under the Credit Facility would be reduced unless we obtain a waiver from the lenders under the Credit Facility. The issuance of additional equity securities could have a dilutive effect on the value of our common stock.
Our cash flows provided by operating activities and access to capital are subject to a number of variables, including:
• our proved reserves;
• the amount of crude oil and natural gas we are able to produce from new and existing wells;
• the prices at which our crude oil and natural gas are sold;
• the costs of developing and producing our crude oil and natural gas;
• our ability to acquire, locate, and produce new reserves;
• the ability and willingness of our banks to lend; and
• our ability to access the equity and debt capital markets.
If the borrowing base under the Credit Facility decreases or if our revenues decrease as a result of lower crude oil or natural gas prices, operating difficulties, declines in reserves, or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations. If additional capital is needed, we may not be able to obtain debt or equity financing on favorable terms, or at all. If cash generated by operations or cash available under the Credit Facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our undeveloped leases and a decline in our crude oil and natural gas reserves, and an adverse effect on our business, financial condition, and results of operations.
Risks Related to Legislative and Regulatory Initiatives
We are subject to health, safety, and environmental laws and regulations that may expose us to significant costs and liabilities.
We are subject to stringent and complex federal, state, and local laws and regulations governing public health and occupational safety, the discharge of materials into the environment, noise emittance, light emittance, and the general protection of the environment and wildlife. These laws and regulations may impose numerous requirements on our operations, including the obligation to obtain a permit before conducting drilling or underground injection activities; restrictions on the types, quantities, and concentration of materials that may be released into the environment; limitations or prohibitions of drilling or completion activities; the application of specific health and safety criteria to protect the public or workers; and the responsibility for cleaning up pollution resulting from operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminalpenalties; the imposition of investigatory or remedial obligations; the issuance of injunctions limiting or preventing some or all of our operations; delays in granting permits; or even the cancellation of leases and/or permits.
There is an inherent risk of incurring significant environmental costs and liabilities in our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions into air, water, and the environment, the underground injection or other disposal of our wastes, the use and disposition of hydraulic fracturing fluids, and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we may be liable for the full cost of removing or remediating contamination, regardless of whether we were at fault, and even when multiple parties contributed to the release and the contaminants were released in compliance with all applicable laws then in effect. In addition, accidental spills or releases on or off our properties may expose us to significant liabilities that could have a material adverse effect on our financial condition or results of operations. Aside from government agencies, the owners of properties where our wells are located, the owners or operators of facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal or otherwise come to be located, and other private parties may be able to sue us to enforce compliance with environmental laws and regulations, collect penalties for violations, or obtain damages for any related personal injury, or damage and property damage, and certain trustees may seek natural resource damages. Some sites we operate are located near current or former third-party crude oil and natural gas operations or facilities, and there is a risk that historic contamination has migrated from those sites to ours. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly requirements could require us to make significant expenditures to attain and maintain compliance or may otherwise have a material adverse effect on our own results of operations, competitive position, or financial condition. We may not be able to recover some or any of these costs from insurance.
Evolving legislation or regulatory initiatives, including those related to hydraulic fracturing, could result in increased costs and additional operating restrictions or delays.
We are subject to extensive federal, state, and local laws and regulations, including those concerning public and occupational health and safety and environmental protection. Governmental authorities frequently review, revise, and supplement these requirements, and both oil and gas development generally, and hydraulic fracturing specifically, are receiving increasing legislative and regulatory attention. For example, the states in which we operate have implemented or are considering additional regulations governing a range of topics, including facility siting, development approvals, cumulative impacts, asset transfers, pollution standards, hearings and variances, groundwater monitoring, underground injection control and enhanced recovery wells, venting and flaring restrictions, spill reporting, cleanup responsibility, wildlife protection, and financial assurance.
Our operations utilize hydraulic fracturing, an important and commonly used process in the completion of crude oil and natural gas wells in low-permeability formations. Hydraulic fracturing involves the injection of water, proppant, and chemicals under pressure into rock formations to stimulate hydrocarbon production. In some instances, certain state and local governments are adopting new requirements on hydraulic fracturing and other oil and gas operations. Some counties in Colorado, for instance, have amended their land use regulations to impose new siting and other requirements on oil and gas development, while other local governments have entered memoranda of agreement with oil and gas producers to accomplish the same or similar objectives. Under current Colorado law, local governments can regulate both facility siting and the surface impacts associated with oil and gas development, and local government regulations may be more protective or stricter than State requirements. In addition, voters in Colorado have proposed or advanced ballot initiatives restricting or banning oil and gas development in Colorado. Because a significant portion our operations and reserves are located in Colorado, the risks we face with respect to such ballot initiatives are greater than other companies with more geographically diverse operations.
The adoption of future federal, state, or local laws or implementing regulations imposing new environmental, operational, and/or financial assurance obligations on, or otherwise limiting, our operations could make it more difficult, more expensive, and/or impossible to complete crude oil and natural gas wells, increase our costs of compliance operations, delay or prevent the development of certain resources (including especially shale formations that are not commercial without the use of hydraulic fracturing), or alter the demand for and consumption of our products. We cannot assure that any such outcome would not be material, and any such outcome could have a material adverse impact on our cash flows and results of operations.
We face increasing risk associated with the long-term trend toward increased activism against oil and gas exploration and development activities in the states in which we operate, particularly in Colorado.
Opposition toward oil and gas drilling and development activity has been growing globally. Companies in the oil and gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, environmental compliance, and business practices. Certain activists are working to, among other things, reduce access to fee, federal, and state government lands, and delay or cancel certain projects such as the development of oil or gas shale plays. For example, environmental activists continue to advocate for increased regulations or bans on shale drilling in the U.S., even in jurisdictions that are among the most stringent in their regulation of the industry. Further efforts could result in the following:
• delay or denial of drilling permits;
• increased local government rulemaking and/or changes to current local government rules that result in increased costs and delay or prevention of oil and gas development;
• increased demands for additional best management practices beyond what is currently required in certain operating agreements or by state regulators;
• revocation or modification of drilling permits, operating agreements, or other necessary authorizations;
• disputes focused on the validity of active leases and record title ownership to prevent development;
• disputes focused on proximity of operations to urban and suburban communities;
• restrictions on installation or operation of production, gathering, or processing facilities;
• mandatory and excessivesetbacks between drilling locations and structures and building units and/or bodies of water, disproportionately impacted communities, or other protected areas;
• restrictions on the use of certain operating practices, such as hydraulic fracturing, or the disposal of related waste materials, such as hydraulic fracturing fluids and produced water;
• increased severance and/or other taxes;
• cyber-attacks;
• legal challenges or lawsuits;
• negative publicity about us or the oil and gas industry in general;
• increased costs of operations and development;
• reduction in demand for our products; and
• other adverse effects on our ability to develop our properties and expand production.
Specifically in Colorado, anti-development activity has both increased and become more effective in recent years. In April 2019, new legislation became effective in Colorado, which substantially changed the state’s regulation of oil and gas exploration and production activities.
Among the most significant changes under the legislation was the provision giving local governments greater control over facility siting and surface impacts associated with oil and gas development. Whether an applicable local government determines to implement regulatory changes is optional, but if changes are adopted, the resulting regulations may be stricter than state requirements. Further, local governments may now inspect oil and gas operations and impose fines for leaks, spills, and emissions. Regulation in the municipalities and areas where we operate could result in increased costs, delays in securing permits and other approvals related to our operations, and otherwise materially bear on our ability to operate and drill new wells in the areas where we hold oil and gas interests. At this time, it is impossible to estimate the potential impact on our business of future local actions on our ability to operate and/or drill oil and gas wells in these areas.
Permitting delays that result from the new ECMC rules and regulations or other state rules and regulations could substantially curtail our near-term pace of new crude oil and natural gas development. We have observed a decline in the pace at which permit applications are being granted in Colorado, and if this trend continues in any of the states in which we operate, it could have a material adverse effect on our business, financial condition, production targets, and results of operations.
Rules adopted by regulators in the states in which we operate may significantly increase our operating costs and have a material adverse effect on our business, financial condition, and results of operations. See “ Item 1. Business - Regulation of the Crude Oil and Natural Gas Industry ” for more information regarding the new and proposed state environmental regulations applicable to our business.
In addition, there have been several citizen/activist lawsuits filed against industry and state and local regulators associated with air quality, siting, environmental justice, and climate change. Such anti-development efforts are likely to continue in the future, which could result in dramatically reducing the area of future oil and gas development in the states in which we conduct our operations. These efforts could have a material adverse effect on our business, financial condition, and results of operations.
SB 181’s requirement, which applies to our Colorado operations, that we own or control more than 45% of the working or mineral interest in order to statutorily pool our applicable interest may make it much more difficult for us to develop such interests, which could have a material adverse effect on our business, financial condition, and results of operations.
With respect to our operations in the DJ Basin in Colorado, in some cases, we do not own more than 45% working interest or mineral interest in a prospective area of development, which is now required to statutorily pool our applicable working or mineral interests. In such cases, unless we can obtain the consent of more than 45% of all applicable working or mineral interest owners (who can be located through reasonable diligence) to pursue statutory pooling, or achieve a voluntary pooling agreement with 100% of the applicable interest owners, we may be prohibited from developing the resources in that area or having them be developed by other operators.
Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
There is a broad consensus of scientific opinion that human-caused (anthropogenic) emissions of GHGs are linked to climate change. Climate change and the costs that may be associated with its impacts and the regulation of GHGs have the potential to affect our business in many ways, including negatively impacting the costs we incur in providing our products and the demand for and consumption of our products (due to potential changes in both costs and weather patterns).
The EPA adopted regulations requiring the reporting of GHG emissions from specific categories of higher GHG emitting sources in the U.S., including certain crude oil and natural gas production facilities, which include certain of our operations. Information in such reporting may form the basis for further GHG regulation. Further, the EPA has continued with its comprehensive strategy for further reducing methane emissions from oil and gas operations, with a final rule being issued in June 2016 as part of the Subpart OOOOa NSPS. In November 2021, the EPA issued a proposed rule intended to reduce methane emissions from oil and gas sources. The proposed rule sought to make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the proposed rule sought to establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental proposed rule removed an emissions monitoring exemption for small wellhead-only sites and created a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters.” The EPA announced a final rule in December 2023, which, among other things, requires the phase out of routine flaring of natural gas from new crude oil wells and routine leak monitoring at all well sites and compressor stations. Notably, EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance dates under state plans. The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing methane from existing sources until March 2026. The final emissions guidelines under Subpart OOOOc provide until 2029 for existing sources to comply. The final rule is subject to ongoing litigation but remains in effect. The EPA’s GHG rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. However, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are undulyburdensome on the identification, development, or use of domestic energy resources. Consequently, future implementation and enforcement of the final rule remains uncertain at this time.
In the meantime, many states already have taken such measures, which have included renewable energy standards, development of GHG emission inventories or cap and trade programs, and the adoption of ambitious climate action targets in Colorado under HB 19-1261.
The adoption and implementation of new or more stringent federal, state, or local legislation or regulatory programs to reduce emissions of GHGs (including carbon pricing schemes), or that require reporting of GHG emissions or other climate-related information, could adversely affect our business and our industry, including by requiring us to incur increased operating costs, such as costs to purchase and operate emissions and vapor control systems, to acquire emissions allowances, or to comply with new regulatory or reporting requirements as well as by restricting our ability to execute on our business strategy, reducing our access to financial markets, or creating greater potential for governmental investigations or litigation. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the crude oil and natural gas we produce. While the Supreme Court’s decision in Loper Bright Enterprises v. Raimondo to overrule Chevron U.S.A. Inc. v.
Natural Resources Defense Council, Inc. and end the concept of general deference to regulatory agency interpretations of laws introduces new complexity for federal agencies and administration of climate change policy and regulatory programs, many of these initiatives are expected to continue. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition, and results of operations. Moreover, incentives to conserve energy or use alternative energy sources as a means of addressing climate change could reduce demand for the crude oil and natural gas we produce. In addition, any enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors. See “ Item 1. Business - Climate Change ” for a further discussion of the laws and regulations related to GHGs and climate change.
Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere and climate change may produce significant physical effects on weather conditions, such as increased frequency and severity of droughts, wildfires, storms, floods, and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the crude oil or natural gas produced or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves, which may not be fully insured. Potential adverse effects could include more stringent air emissions regulations and disruption of our production activities, including, for example, damages to our facilities from winds or floods, increases in our costs of operation, or reductions in the efficiency of our operations, increases in market prices of or limited access to raw materials such as energy and water, impacts on our personnel, supply chain, or distribution chain, as well as potentially increased costs for and availability of insurance coverages in the aftermath of such effects. Any of these effects could have an adverse effect on our assets and operations. Our ability to mitigate the adverse physical impacts of climate change depends in part upon our disaster preparedness and response and business continuity planning. Further, energy needs could increase or decrease as a result of extreme weather conditions depending on the duration and magnitude of any such climate changes. Increased energy use due to weather changes may require us to invest in additional equipment to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. The effect of fluctuations on supply and demand may become more pronounced within specific geographic crude oil and natural gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
Transition risks related to climate change, including negative shift in investor sentiment with respect to the oil and gas industry, could have material and adverse effects on us.
Increasing attention from governmental and regulatory bodies, investors, consumers, industry, and other stakeholders on combatting climate change, together with changes in consumer and industrial/commercial behavior, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary climate-related disclosures, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in the enactment of climate change-related regulations, policies, and initiatives (at the government, regulator, corporate, and/or investor community levels), including alternative energy requirements, new fuel consumption standards, energy conservation and emissions reductions, measures and responsible energy development; technological advances with respect to the generation, transmission, storage, and consumption of energy (including advances in wind, solar, and hydrogen power, as well as battery technology); increased availability of, and increased demand from consumers and industry for, energy sources other than crude oil and natural gas (including wind, solar, nuclear, and geothermal sources as well as electric vehicles); and development of, and increased demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services. These developments may in the future adversely affect the demand for products manufactured with, or powered by, petroleum products, as well as the demand for, and in turn the prices of, the products that we sell, our stock price and access to capital markets, and the availability to us of necessary third-party services and facilities that we rely on, which may increase our operational costs and adversely affect our ability to successfully carry out our business strategy.
Furthermore, the crude oil and natural gas industry, and energy industry more broadly, is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, including technological advances in fuel economy and energy generation devices or other technological advances that could reduce demand for crude oil and natural gas, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement new technologies at substantial costs. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition, or results of operations could be materially and adversely affected.
Certain segments of the investor community have developed negative sentiment towards investing in our industry, and such negative sentiment and related reputational risks may also adversely affect our ability to successfully carry out our business strategy by adversely affecting our access to capital. In addition, some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments, and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. There is also a risk that financial institutions may be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector, and certain investment banks and asset managers based both domestically and internationally have announced that they are adopting climate change guidelines for their banking and investing activities. Institutional lenders who provide financing to energy companies such as ours have also become more attentive to sustainable lending practices, and some may elect not to provide traditional energy producers or companies that support such producers with funding. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects. Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding or higher cost of capital for potential development projects as well as the restriction, delay, or cancellation of infrastructure projects and energy production activities, ultimately impacting our future financial results.
Additionally, negative public perception regarding us and/or our industry may lead to increased regulatory, legislative, and judicial scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines, and enforcement interpretations. Additionally, environmental groups, landowners, local groups, and other advocates may oppose our operations through organized protests, attempts to block or sabotage our operations or those of our midstream transportation providers, intervene in regulatory or administrative proceedings involving our assets or those of our midstream transportation providers, or file lawsuits or other actions designed to prevent, disrupt, or delay the development or operation of our assets and business or those of our midstream transportation providers. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens, and increased risk of litigation. Further, a number of cities and other local governments have sought to bring suit against the largest oil and gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but failed to adequatelydisclose such impacts to their investors or customers. Private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages, or other liabilities. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.
Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business. In addition, various officials and candidates at the federal, state, and local levels have made climate-related pledges or proposed banning hydraulic fracturing altogether. More broadly, the enactment of climate change-related policies and initiatives across the market at the corporate level and/or investor community level may in the future result in increases in our compliance costs and other operating costs and have other adverse effects (e.g., greater potential for governmental investigations or litigation). For further discussion regarding the transition risks posed to us by climate change-related regulations, policies, and initiatives, see the discussion contained in “ Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects ” .
Increasing scrutiny and changing stakeholder expectations in respect of ESG and sustainability practices may have an adverse effect on our business, financial condition, and results of operations and damage our reputation.
In recent years, companies across all industries are facing increasing scrutiny from a variety of stakeholders, including investor advocacy groups, proxy advisory firms, certain institutional investors, and lenders, investment funds and other influential investors and rating agencies, related to their ESG and sustainability practices. If we do not adapt to or comply with investor or other stakeholder expectations and standards on ESG matters (or meet sustainability goals and targets that we have set), as they continue to evolve, or if we are perceived to have not responded appropriately or quickly enough to growing concern for ESG and sustainability issues, regardless of whether there is a regulatory or legal requirement to do so, we may suffer from reputational damage and our business, financial condition, and/or stock price could be materially and adversely affected.
In addition, our continuing efforts to research, establish, accomplish, and accurately report on the implementation of our sustainability strategy, including any specific sustainability objectives, may also create additional operational risks and
expenses and expose us to reputational, legal, and other risks. While we create and publish voluntary disclosures regarding sustainability matters from time to time, some of the statements in those voluntary disclosures may be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring, and reporting on many sustainability matters. Further, failure or a perception (whether or not valid) of failure to implement our sustainability strategy or achieve sustainability goals and targets we have set, including emissions reduction goals, could damage our reputation, causing our investors or consumers to lose confidence in our Company and negatively impact our operations. Our continuing efforts to research, establish, accomplish and accurately report on the implementation of our sustainability strategy, including any sustainability goals, may also create additional operational risks and expenses and expose us to reputational, legal and other risks. For example, growing interest on the part of investors and regulators in ESG factors and increased demand for, and scrutiny of, ESG-related disclosure by stakeholders has also increased the risk that companies could be perceived as, or accused of, making inaccurate or misleading statements regarding their ESG-related claims, goal, targets, efforts or initiatives, often referred to as “greenwashing.” Such perception or accusation could damage our reputation and result in litigation or regulatory actions. In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital.
Further, our operations and projects require us to have strong relationships with various key stakeholders, including our stockholders, employees, suppliers, customers, local communities, and others. We may face pressure from stakeholders, many of whom are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint, and promote sustainability while at the same time remaining a successfully operating public company. If we do not successfully manage expectations across these varied stakeholder interests, it could erode stakeholder trust and thereby affect our brand and reputation. Such erosion of confidence could negatively impact our business through decreased demand, delays in projects, increased legal action and regulatory oversight, adverse press coverage and other adverse public statements, difficulty hiring and retaining top talent, difficulty obtaining necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms, and difficulty securing investors and access to capital.
Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate, and other risks associated with our business.
The Dodd-Frank Act establishes, among other provisions, federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act also establishes margin requirements and certain transaction clearing and trade execution requirements. The Dodd-Frank Act requires certain parties to derivative contracts to comply with margin requirements, though we likely qualify for a commercial end-user exemption from such requirements. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties.
The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may be more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.
We are subject to federal, state, and local taxes and may become subject to new taxes, and certain federal income tax deductions and state income tax deductions and exemptions currently available with respect to oil and gas exploration and development may be eliminated or reduced as a result of future legislation.
The federal, state, and local governments in the areas in which we operate (i) impose taxes on the crude oil and natural gas products we sell, and (ii) for many of our wells, impose sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur unexpectedly. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals.
There have been proposals for legislative changes that, if enacted into law, would eliminate certain key U.S. federal income tax incentives currently available to crude oil and natural gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination
of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. Any such changes in U.S. federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition, results of operations, and cash flow.
In the states we operate in, there may be proposals for legislative changes that, if enacted into law, could substantially increase our severance tax and ad valorem tax effective rates. Such changes may include, but are not limited to, (i) the reduction or elimination of the credit against severance tax based on the property tax we pay; (ii) the reduction or elimination of certain exemptions impacting severance tax liability; and (iii) increased severance tax rates. Any such changes to ad valorem and severance tax laws in the states we operate in could negatively affect our financial condition, results of operations, and cash flow.
On August 16, 2022, the Inflation Reduction Act was signed into law. Among other things, the Inflation Reduction Act includes a 1% excise tax on corporate stock repurchases, applicable to repurchases after December 31, 2022, and also a new minimum tax based on book income. While we do not currently expect the Inflation Reduction Act to have a material impact on our effective tax rate, it is possible that the Inflation Reduction Act (or implementing regulations and other guidance) could adversely impact our current and deferred federal tax liability.
Changes to federal tax deductions, as well as any changes to or the imposition of new state or local taxes (including production, severance, or similar taxes) could negatively affect our financial condition, results of operations, and cash flow.
Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our financial condition and results of operations.
We are subject to taxes by U.S. federal, state, and local tax authorities. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including changes in the valuation of our deferred tax assets and liabilities, expected timing and amount of the release of any tax valuation allowances, or changes in tax laws, regulations, or interpretations thereof. In addition, we may be subject to audits of our income, sales, and other transaction taxes by U.S. federal, state, and local taxing authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations.
Certain past transactions triggered a limitation on the utilization of our historic U.S. NOLs and the NOLs acquired in such transactions.
Our ability to utilize NOLs (including NOLs acquired in certain prior transactions) to reduce future taxable income following such transactions depends on many factors, including our future income, which cannot be assured. Section 382 of the Internal Revenue Code generally imposes an annual limitation upon the occurrence of an “ownership change” resulting from issuances of a company’s stock or the sale or exchange of such company’s stock by certain stockholders if, as a result, there is an aggregate change of more than 50% in the beneficial ownership of such company’s stock by such stockholders within a rolling three-year period. The limitation with respect to such loss carryforwards generally would be equal to (i) the fair market value of the company’s equity immediately prior to the ownership change multiplied by (ii) a percentage approximately equivalent to the yield on long-term tax-exempt bonds during the month in which the ownership change occurs. We believe that ownership changes occurred as a result of the aforementioned transactions with respect to us and the entities involved in such transactions, which triggered a limitation (calculated as described above) on our ability to utilize any historic NOLs following such transactions. In addition, the NOLs from one of the companies acquired in such transactions are further limited under Section 382 of the Internal Revenue Code as a result of a prior ownership change that occurred.
Continuing or worsening inflationary pressures and associated changes in monetary policy may result in increases to the cost of our goods, services, and personnel, which in turn could cause our capital expenditures and operating costs to rise.
Inflation has been an ongoing concern in the U.S. since 2021. Ongoing inflationary pressures may result in increases to the costs of our oilfield goods, services, and personnel, which would, in turn, cause our capital expenditures and operating costs to rise. Sustained levels of high inflation could cause the U.S. Federal Reserve and other central banks to increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either of which, or the combination thereof, could hurt the financial and operating results of our business.
Risks Related to Our Common Stock
We have experienced recent volatility in the market price and trading volume of our common stock and may continue to do so in the future.
The trading price of shares of our common stock has fluctuated widely and in the future may be subject to similar fluctuations. As an example, during the 2024 calendar year, the closing sales price of our common stock ranged from a low of $42.79 per share to a high of $78.16 per share. The trading price of our common stock may be affected by a number of factors, including the volatility of crude oil, natural gas, and NGL prices, our operating results, changes in our earnings estimates, additions or departures of key personnel, our financial condition and liquidity, drilling activities, legislative and regulatory changes, general conditions in the crude oil and natural gas exploration and development industry, general economic conditions, and general conditions in the securities markets. In particular, a significant or extended decline in crude oil, natural gas, and NGL prices could have a material adverse effect on the sales price of our common stock. Other risks described in this annual report could also materially and adversely affect our share price.
Although our common stock is listed on the New York Stock Exchange (the “NYSE”), we cannot assure you that an active public market will continue for our common stock or that we will be able to continue to meet the listing requirements of the NYSE. If an active public market for our common stock does not continue, the trading price and liquidity of our common stock will be materially and adversely affected. If there is a thin trading market or “float” for our stock, the market price for our common stock may fluctuate significantly more than the stock market as a whole. Without a large float, our common stock would be less liquid than the stock of companies with broader public ownership and, as a result, the trading prices of our common stock may be more volatile. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us.
Our ability to pay dividends to, or repurchase shares of common stock from, our stockholders is restricted by applicable laws and regulations and requirements under certain of our debt agreements, including the Credit Facility and the indentures governing our senior notes.
The decision to pay any future dividends or conduct future stock repurchases is solely within the discretion of, and subject to approval by, our Board. Our Board’s determination with respect to any such stock repurchases or dividends, including with respect to dividends, the record date, the payment date and the actual amount of the dividend, will depend upon, among other things, our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law, and other factors that our Board deems relevant at the time of such determination. We cannot assure you, however, that we will pay dividends or conduct stock repurchases in the future in the current amounts or at all. Our Board may change the timing and amount of any future stock repurchases or dividend payments or eliminate such stock repurchases or the payment of future dividends to our common stockholders at its discretion, without notice to our stockholders. Our ability to declare and pay dividends to and conduct stock repurchases from our stockholders is subject to certain laws, regulations, and policies, including minimum capital requirements and, as a Delaware corporation, we are subject to certain restrictions on dividends and stock repurchases under the Delaware General Corporation Law (the “DGCL”). Under the DGCL, our Board may not authorize a dividend or repurchase of our common stock unless such dividend or repurchase is either paid for out of our surplus, as calculated in accordance with the DGCL, or if we do not have a surplus, such dividend or repurchase is paid for out of our net profits for the fiscal year in which such dividend is declared or stock repurchase conducted and/or the preceding fiscal year. In addition, our ability to pay cash dividends to and conduct stock repurchases from our stockholders may be limited by covenants in any debt agreements that we are currently a party to, including the Credit Facility and the indentures governing our senior notes, or may enter into in the future. As a consequence of these various limitations and restrictions, we may not be able to make, or may have to reduce or eliminate at any time, the payment of dividends on or repurchase of our common stock. Any elimination of, or revision in, our stock repurchase program or dividend policy could have a material adverse effect on the market price of our common stock.
Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, even if such acquisition or merger may be in our stockholders’ best interests.
Our certificate of incorporation authorizes our Board to issue preferred stock without stockholder approval. If our Board elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:
• advance notice provisions for stockholder proposals and nominations for elections to the Board to be acted upon at meetings of stockholders; and
• limitations on the ability of our stockholders to call special meetings or act by written consent.
Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date such stockholder became an interested stockholder, unless various conditions are met, such as approval of the transaction by our Board.
Our certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, or other employees.
Our certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the sole and exclusive forum shall be the Court of Chancery of the State of Delaware for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any director, officer, employee, or agent of ours to us or to our stockholders, (iii) any action asserting a claim against us arising pursuant to any provision of the DGCL, our certificate of incorporation or our bylaws (or any action to interpret, apply, or enforce any provision thereof), or (iv) any action asserting a claim against us governed by the internal affairs doctrine, in each such case subject to said court of chancery having personal jurisdiction over the indispensable parties named as defendants therein.
Our exclusive forum provision is not intended to apply to claims arising under the Securities Act or the Exchange Act. To the extent the provision could be construed to apply to such claims, there is uncertainty as to whether a court would enforce the forum selection provision with respect to such claims, and in any event, our stockholders would not be deemed to have waived our compliance with federal securities laws and the rules and regulations thereunder. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock is deemed to have received notice of and consented to the foregoing forum selection provision. This provision may limit our stockholders’ ability to bring a claim in a judicial forum that they find favorable for disputes with us or our directors, officers, or other employees, which may discourage such lawsuits. Alternatively, if a court were to find this choice of forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition, prospects, or results of operations.
premier
leadership
Financial and Operating Results
Our financial and operational results for the year ended December 31, 2024:
• Total sales volumes increased 63% when compared to the year ended December 31, 2023; average sales volumes per day increased to 345 MBoe/d compared to 212 MBoe/d during the year ended December 31, 2023, in each case, primarily as a result of the Hibernia, Tap Rock and Vencer Acquisitions;
• Net income of $838.7 million, or $8.46 per diluted share for the year ended December 31, 2024 compared to $784.3 million, or $9.02 per diluted share for the year ended December 31, 2023;
• Cash flows provided by operating activities were $2.9 billion compared to $2.2 billion during the year ended December 31, 2023. Adjusted Free Cash Flow (1) was $1.3 billion compared to $795.9 million during the year ended December 31, 2023;
• Capital expenditures in drilling, completions, facilities, land, midstream assets, and other were $1.9 billion;
• Cash dividends paid of $493.8 million;
• Repurchased approximately 7.3 million shares of our common stock totaling $427.2 million at a weighted average price of $58.42 per share; and
• Proved reserves increased by 14% to 797.7 MMBoe when compared to December 31, 2023, primarily as a result of the Vencer Acquisition.
(1) Adjusted Free Cash Flow is a non-GAAP financial measure. Refer to “ Non-GAAP Financial Measures - Reconciliation of Adjusted Free Cash Flow to Cash Provided by Operating Activities ” and “ Liquidity and Capital Resources ” below for additional discussion.
2024 Transaction and Operations
On January 2, 2024, we completed the acquisition of certain crude oil and natural gas assets from Vencer. The Vencer Acquisition included approximately 44,000 net acres in the Midland Basin, which is part of the larger Permian Basin, and certain related crude oil and natural gas assets with average production of approximately 49 MBoe per day as of January 2, 2024 in exchange for aggregate adjusted consideration of approximately $2.0 billion, consisting of $1.0 billion in cash paid at the closing of the Vencer Acquisition, 7.2 million shares of our common stock issued at the closing of the Vencer Acquisition, and $550.0 million in cash to be paid on or before January 3, 2025, inclusive of customary post-closing adjustments. In 2024, we made two early payments totaling $75.0 million towards the deferred consideration. The remaining balance of $475.0 million was paid on January 3, 2025. The initial cash portion of the acquisition was funded by cash on hand and the issuance of $1.0 billion in aggregate principal amount of our 2030 Senior Notes. Refer to “ Item 8. Financial Statements and Supplementary Data - Note 2 - Acquisitions and Divestitures ” and “ Item 8. Financial Statements and Supplementary Data - Note 5 - Debt ” for additional discussion.
During 2024, our total capital expenditures in drilling, completions, land, and midstream assets were $1.9 billion. In the DJ Basin, we operated approximately 1.3 drilling rigs and 1.5 completion crews, allowing us to drill 85 gross (75.1 net) operated wells and turn to sales 115 gross (103.9 net) operated wells. In the Permian Basin, we operated approximately 4.5 drilling rigs and 2.0 completion crews, allowing us to drill 122 gross (114.0 net) operated wells and turn to sales 122 gross (107.6 net) operated wells.
Commodity Prices and Certain Other Market Conditions
The crude oil and natural gas industry is cyclical and commodity prices are inherently volatile. Commodity prices in 2024 continued to be impacted by various macro-economic factors influencing the balance of supply and demand. From January through April 2024, pricing for crude oil rebounded when compared to declining pricing in the fourth quarter of 2023. The rebound was a result of concerns over lower oil supply driven by uncertainties around political conditions in or affecting other crude oil producing countries, including the Israel-Palestine conflict. Additionally, in the first half of 2024, OPEC+ continued production cuts to seek to stabilize the crude oil market. Despite OPEC+’s efforts to constrain production, non-OPEC+ countries continue to have an impact on pricing by increasing overall output in the second half of 2024, including the U.S., which production reached a monthly record in October 2024. Further, weakening global economic growth has been contributing downward pressure on the price of oil, with OPEC+ consistently reducing consumption estimates throughout 2024 as a result of China’s economic slowdown, specifically in the transportation sector. These factors have led to declining monthly average crude oil prices in the second half of 2024 to the lowest levels seen since 2021.
U.S. inflation rates during 2024 remained relatively stable when compared to 2023, yet slightly higher than historical averages. Inflationary pressures can create economic slowdown and/or lead to a recession. A slowdown or recession can cause a decrease in short-term or longer-term demand for commodities, resulting in oversupply and potential for lower commodity prices. Lower prices and inflationary costs could impact our drilling program. The foregoing destabilizing factors have caused dramatic fluctuations in global financial markets and uncertainty about world-wide crude oil and natural gas supply and demand, which in turn has increased the volatility of crude oil and natural gas prices.
The below graph depicts monthly average NYMEX WTI crude oil and NYMEX HH natural gas price over the years ended December 31, 2024 and 2023.
(1) The average NYMEX WTI crude oil price for the years ended December 31, 2024 and 2023 was $75.72 and $77.62, respectively.
(2) The average NYMEX natural gas HH price for the years ended December 31, 2024 and 2023 was $2.27 and $2.74, respectively.
In light of uncertainty associated with crude oil and natural gas demand, future monetary policy relating to inflationary pressures, and governmental policies aimed at transitioning toward lower carbon energy, we cannot predict any future volatility in or levels of commodity prices or demand for crude oil and natural gas.
We receive a premium or discount to the benchmark WTI price for our crude oil production. The differential between the benchmark price and the price we receive can reflect adjustments for quality, location, and transportation. Our DJ Basin crude oil price includes a higher-grade quality differential and includes a transportation differential for delivery to Cushing, Oklahoma. Our Permian Basin crude oil price includes a transportation differential for delivery to Cushing, Oklahoma. During the year ended December 31, 2024, this differential was a premium to WTI. However, basis differentials can be volatile and can change at various times given their high correlation with market dynamics, supply and demand, and overall production.
Our natural gas production is typically sold at a discount to the benchmark NYMEX HH price. Our DJ Basin natural gas production is sold based on prices established for CIG and our Permian Basin natural gas production is based on the Waha Hub in West Texas. Pricing we receive for our natural gas in both basins is correlated with the capacity of in-field gathering systems, compression, and processing facilities, as well as transportation pipelines out of the basins, of which are majority owned and operated by third parties. During the year ended December 31, 2024, the Waha Hub experienced periods of negative pricing due to oversupply, seasonal maintenance, and limited pipeline capacity. Toward the end of 2024, Waha Hub prices momentarily rebounded following Energy Transfer's Warrior Pipeline Final Investment Decision announcement, and December settled at $1.95/MMBtu.
We periodically enter into natural gas basis protection swaps to mitigate a portion of our exposure to adverse market changes. As a result of our natural gas derivative contracts, we recorded a cash settlement gain of $48.1 million during the year ended December 31, 2024. Refer to Item 8. Financial Statements and Supplementary Data - Note 9 - Derivatives for further discussion on our derivative contracts.
Outlook
Our 2025 capital investments in drilling, completions, and midstream, which we expect to be between $1.8 billion to $1.9 billion, are focused on the continued execution of our development plans in the DJ Basin and Permian Basin. We have operational flexibility to control the pace of our capital spending and we regularly monitor external factors that may negatively impact it. We may revise our capital program during the year as a result of this.
Our 2025 capital program allocates slightly more to the Permian Basin as compared to the DJ Basin and level-loads investment to support sustainable capital efficiencies and reduced quarterly volatility, with spend estimated to be 55% in the first half of 2025 compared to 63% in the first half of 2024. The 2025 capital investment plan is anticipated to deliver between 325 to 335 MBoe per day on average for the year. We continue to incorporate capital spend from our budget towards emission reduction projects, compliance with regulations, and the purchase of carbon credits and renewable energy credits. We do not presently anticipate the occurrence of any material effects on our business, financial condition, or results of operations in future periods as a result of capital designated on these initiatives.
Results of Operations
The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto contained in Item 8 of this Annual Report on Form 10-K. Comparative results of operations for the period indicated are discussed below.
The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated:
Year Ended December 31,
Change
Percent Change
Revenues (in thousands):
Crude oil sales
Natural gas sales
NGL sales
Product revenue
Sales Volumes:
Crude oil (MBbls)
Natural gas (MMcf)
NGL (MBbls)
Total sales volumes (MBoe)
Average Sales Prices (before derivatives):
Crude oil (per Bbl)
Natural gas (per Mcf)
NGL (per Bbl)
Total (per Boe)
Average Sales Prices (after derivatives) (1) :
Crude oil (per Bbl)
Natural gas (per Mcf)
NGL (per Bbl)
Total (per Boe)
(1) Average sale prices, after derivatives is a non-GAAP financial measure. For a reconciliation of average sales price, before derivatives to average sales price, after derivatives, see Non-GAAP Financial Measures below.
The following table presents crude oil, natural gas, and NGL sales volumes by operating region for the periods presented:
Year Ended December 31,
Percent Change
Crude oil (MBbls)
DJ Basin
Permian Basin
Total
Natural gas (MMcf)
DJ Basin
Permian Basin
Total
NGL (MBbls)
DJ Basin
Permian Basin
Total
Total sales volumes (MBoe)
DJ Basin
Permian Basin
Total
Average sales volumes per day (MBoe/d)
DJ Basin
Permian Basin
Total
The following table sets forth information regarding crude oil, natural gas, and NGL sales prices, excluding the impact of commodity derivatives, and production costs for the periods presented.
Year Ended December 31,
Percent Change
Average Sales Price
Crude Oil (Per Bbl)
DJ Basin
Permian Basin
Total
Natural gas (Per Mcf)
DJ Basin
Permian Basin
Total
NGL (Per Bbl)
DJ Basin
Permian Basin
Total
Production Cost (Per Boe) (1)
DJ Basin
Permian Basin
Total
(1) Represents lease operating expense and midstream operating expense per Boe using total sales volumes and excludes ad valorem and severance taxes.
Crude oil, natural gas, and NGL sales. Total product revenues increased by 50% to $5.2 billion for the year ended December 31, 2024 compared to $3.5 billion for the year ended December 31, 2023. The increase was primarily due to a 63% increase in total sales volumes driven by the Hibernia, Tap Rock, and Vencer acquisitions, partially offset by an 8% decrease in total commodity pricing, excluding the impact of derivatives, with natural gas as the predominate driver.
The following table summarizes our operating expenses for the periods indicated (in thousands, except per Boe amounts):
Year Ended December 31,
Change
Percent Change
Operating Expenses:
Lease operating expense
Midstream operating expense
Gathering, transportation, and processing
Severance and ad valorem taxes
Exploration
Depreciation, depletion, and amortization
Transaction costs
General and administrative expense
Other operating expense
Total operating expenses
Selected Operating Expenses (per Boe):
Lease operating expense
Midstream operating expense (1)
Gathering, transportation, and processing
Severance and ad valorem taxes
Depreciation, depletion, and amortization
Transaction costs
General and administrative expense
Total selected operating expenses (per Boe)
** Percent not meaningful
(1) Our midstream assets predominantly relate to our DJ Basin operations. If we were to exclude the production of our Permian Basin assets from this calculation, it would result in a $0.06 per Boe, or 8% increase between the year ended December 31, 2024 and 2023.
Lease operating expense. Lease operating expense increased 92%, to $577.8 million for the year ended December 31, 2024, from $301.3 million for the year ended December 31, 2023, and increased 18% on an equivalent basis per Boe. The increase in lease operating expense was primarily the result of the Tap Rock, Hibernia, and Vencer acquisitions in the Permian Basin. Additionally, our assets in the Permian Basin incurred additional costs for planned maintenance, workover projects, and workover optimizations in the last half of 2024. These increases were slightly offset by the Vencer Acquisition and 2024 development activities in areas of the Permian Basin with lower operating costs. The increase in lease operating expense per Boe was a result of the increased cost of operatorship in the Permian Basin relative to the DJ Basin.
Gathering, transportation, and processing. Gathering, transportation, and processing (“GTP”) expense increased 30%, to $377.7 million for the year ended December 31, 2024, from $290.6 million for the year ended December 31, 2023, and decreased 20% on an equivalent basis per Boe. The increase was primarily driven by (i) an increase in natural gas and NGL volumes processed from the Hibernia, Tap Rock, and Vencer acquisitions for a select number of midstream contracts where costs are incurred prior to the transfer of control for approximately $55.0 million, (ii) an increase in production in the DJ Basin under contract terms that are incurred prior to the transfer of control for approximately $30.0 million, and (ii) a slight increase in all GTP contracts as a result of annual price escalations. GTP expense per Boe decreased period over period as, with respect to a significant portion of the midstream contracts assumed in the Hibernia, Tap Rock, and Vencer acquisitions, GTP costs are incurred subsequent to the transfer of control; thereby, these costs are recorded net within crude oil, natural gas, and NGL sales.
Severance and ad valorem taxes. Severance taxes represent taxes imposed by the states in which we operate based on the value of the crude oil, natural gas, and NGL we produce. Ad valorem taxes represent taxes imposed by specific jurisdictions in which we operate based on the assessed value of our properties in that region. For our operations in Texas, the assessed value of our properties is determined using a discounted cash flow methodology. For our operations in Colorado and New Mexico, assessed value is determined by the value of the crude oil, natural gas, and NGL sold less various costs incurred for transportation and processing.
Severance and ad valorem taxes increased 36%, to $377.4 million for the year ended December 31, 2024, from $276.5 million for the year ended December 31, 2023, and decreased 16% on an equivalent basis per Boe. Crude oil, natural gas, and NGL sales increased by 50% for the year ended December 31, 2024 when compared to the year ended December 31, 2023, resulting in higher severance and ad valorem taxes on an absolute basis. The decrease in severance and ad valorem taxes per Boe was primarily due to an increase in crude oil, natural gas, and NGL sales generated through the Hibernia and Vencer acquisitions in the state of Texas, which generally levies lower severance and ad valorem tax rates relative to the states of Colorado and New Mexico.
Depreciation, depletion, and amortization. Depreciation, depletion, and amortization (“DD&A”) expense increased 76%, to $2.1 billion for the year ended December 31, 2024 from $1.2 billion for the year ended December 31, 2023, and increased 8% on an equivalent basis per Boe. Subsequent to December 31, 2023, we invested approximately $3.7 billion in the acquisition and development of crude oil and natural gas properties. The increase in total DD&A expense was primarily due to a 63% increase in sales volumes between periods driven by the Hibernia, Tap Rock, and Vencer acquisitions. The increase in DD&A expense per Boe was due to an increase in the depletion rate driven by a greater increase in the depletable property base in proportion to proved reserves.
Transaction costs. During the year ended December 31, 2024, we incurred $31.4 million in legal, advisor, and other costs associated with the Vencer Acquisition and subsequent integration, in addition to our divestiture of certain non-core assets in the DJ Basin. During the year ended December 31, 2023, we incurred $84.3 million in short-term financing fees as well as legal, advisor, and other costs associated with the Hibernia, Tap Rock, and Vencer acquisitions. Refer to “ Item 8. Financial Statements and Supplementary Data - Note 2 - Acquisitions and Divestitures ” for additional discussion over our acquisitions.
General and administrative expense. General and administrative expense increased 41%, to $227.0 million for the year ended December 31, 2024, from $161.1 million for the year ended December 31, 2023, and decreased 13% on an equivalent basis per Boe. The increase in general and administrative expense was primarily driven by the growth in headcount and associated costs as a result of the addition of operations in the Permian Basin. General and administrative expense per Boe decreased due to a 63% increase in sales volumes.
Derivative gain. Our derivative gain for the year ended December 31, 2024 was $37.5 million, as compared to a gain of $9.3 million for the year ended December 31, 2023. Our derivative gain for the year ended December 31, 2024 was due to fair market value adjustments resulting from lower market prices relative to our open positions and cash settlement net gains. Our derivative gain for the year ended December 31, 2023 was due to fair market value adjustments resulting from lower market prices relative to our open positions, partially offset by cash settlement losses. Refer to “ Item 8. Financial Statements and Supplementary Data - Note 9 - Derivatives ” for additional discussion.
Interest expense. Interest expense for the years ended December 31, 2024 and 2023 was $456.3 million and $182.7 million, respectively. The increase in interest expense was attributable to the debt issued in conjunction with the financing of the Hibernia, Tap Rock, and Vencer acquisitions. Average debt outstanding for the years ended December 31, 2024 and 2023 was $4.9 billion and $2.1 billion, respectively. The components of interest expense for the periods presented are as follows (in thousands):
Year Ended December 31,
Senior Notes
Credit Facility
Commitment and letter of credit fees under the Credit Facility
Amortization of deferred financing costs and deferred acquisition consideration
Other
Total interest expense
Income tax expense . Our effective tax rate differs from the amount that would be provided by applying the statutory United States federal income tax rate of 21% to income before income taxes due to the effect of state income taxes, excess tax benefits and deficiencies on stock-based compensation awards, tax limitations on compensation of covered individuals, tax credits, and other permanent differences. Refer to “ Item 8. Financial Statements and Supplementary Data - Note 12 - Income Taxes” for additional discussion.
Our income tax expense for the years ended December 31, 2024 and 2023 was $244.0 million and $215.2 million, resulting in an effective tax rate of 22.5% and 21.5%, respectively, on income from operations before income taxes. During the year ended December 31, 2024, income tax expense was additionally impacted by deferred tax benefits from the state apportionment changes as a result of the Vencer Acquisition. During the year ended December 31, 2023, income tax expense was additionally impacted by deferred tax benefits from state apportionment changes as a result of the Hibernia and Tap Rock acquisitions.
Liquidity and Capital Resources
Our primary sources of liquidity include cash flows from operating activities, available borrowing capacity under the Credit Facility, potential proceeds from equity and/or debt capital markets transactions, potential proceeds from sales of assets, and other sources. We may use our available liquidity for operating activities, working capital requirements, capital expenditures, acquisitions, debt reduction, the return of capital to stockholders, and for general corporate purposes.
Our primary source of cash flows from operating activities is the sale of crude oil, natural gas, and NGL. As such, our cash flows are subject to significant volatility due to changes in commodity prices, as well as variations in our sales volumes. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, the impact of inflation and monetary policy, weather, product distribution, transportation, processing, and refining capacity, regulatory constraints, and other supply chain dynamics, among other factors.
As of December 31, 2024, our liquidity was $1.82 billion, consisting of cash on hand of $75.8 million and $1.75 billion of available borrowing capacity on our Credit Facility. Borrowing capacity under the Credit Facility is primarily based on the value assigned to the proved reserves attributable to our crude oil and natural gas interests. As of February 21, 2025, the available borrowing capacity on our Credit Facility was $1.70 billion. Our Credit Facility is set to mature in August 2028, with the next scheduled borrowing base redetermination date to occur in May 2025.
The Credit Facility contains customary representations and various affirmative and negative covenants as well as certain financial covenants, including (a) a permitted net leverage ratio of not greater than 3.00 to 1.00, (b) a current ratio, inclusive of the unused commitments under the Credit Facility then available to be borrowed, of not less than 1.00 to 1.00, and (c) upon the achievement of investment grade credit ratings, a PV-9 coverage ratio of the net present value, discounted at 9% per annum, of the estimated future net revenues expected in the proved reserves to our total net indebtedness of not less than 1.50 to 1.00 (“PV-9 Coverage Ratio”). We were in compliance with all covenants under the Credit Facility as of December 31, 2024, and through the filing of this Annual Report on Form 10-K. Refer to “ Item 8. Financial Statements and Supplementary Data - Note 5 - Debt ” for additional information.
Our material short-term cash requirements include: operating activities, working capital requirements, capital expenditures, dividends, and payments of contractual obligations, including the payment of the remaining portion of the deferred consideration due with respect to the Vencer Acquisition. Our material long-term cash requirements from various contractual and other obligations include: debt obligations and related interest payments, firm transportation and minimum volume agreements, taxes, asset retirement obligations, and leases. Refer to "Item 8. Financial Statements and Supplementary Data” for additional information.
Our future capital requirements, both near-term and long-term, will depend on many factors, including, but not limited to, commodity prices, market conditions, our available liquidity and financing, acquisitions and divestitures of crude oil and natural gas properties, the availability of drilling rigs and completion crews, the cost of completion services, success of drilling programs, land and industry partner issues, weather delays, the acquisition of leases with drilling commitments, and other factors. We regularly consider which resources, including debt and equity financing, are available to meet our future financial obligations, planned capital expenditures, and liquidity requirements.
Funding for these requirements may be provided by any combination of the sources of liquidity outlined above. We expect our 2025 capital program to be funded by cash flows from operations. Although we cannot provide any assurance, based on our projected cash flows from operations, our cash on hand, and available borrowing capacity on our Credit Facility, we believe that we will have sufficient capital available to fund these requirements through the 12-month period following the filing of this Annual Report on Form 10-K, and based on current expectations, the long-term.
Sources and Uses of Cash and Cash Equivalents
The following table presents the sources and uses of our cash and cash equivalents for the periods presented (in thousands):
Year Ended December 31,
Activity Type
Sources of Cash and Cash Equivalents
Net cash provided by operating activities
Operating
Proceeds from property transactions
Investing
Proceeds from credit facility
Financing
Proceeds from issuance of senior notes
Financing
Other, net
Investing/Financing
Total sources of cash and cash equivalents
Uses of Cash and Cash Equivalents
Acquisitions of businesses, net of cash acquired
Investing
Acquisitions of crude oil and natural gas properties
Investing
Capital expenditures for drilling and completion activities and other fixed assets
Investing
Deposits for acquisitions
Investing
Payments to credit facility
Financing
Dividends paid
Financing
Common stock repurchased and retired
Financing
Other, net
Investing/Financing
Total uses of cash and cash equivalents
Net change in cash and cash equivalents
Sources of Cash and Cash Equivalents
Our sources of cash and cash equivalents decreased by $3.1 billion year over year, primarily driven by the 2023 issuances of an aggregate principal amount of $3.7 billion from our 2028 Senior Notes, 2030 Senior Notes, and 2031 Senior Notes. The net cash proceeds from such issuances were used to fund the Hibernia and Tap Rock acquisitions in 2023 and the Vencer Acquisition in 2024.
Our net cash flows from operating activities are primarily impacted by commodity prices, sales volumes, net settlements from our commodity derivative positions, operating costs, and general and administrative expenses. Net cash provided by operating activities increased by $626.5 million during the year ended December 31, 2024, compared to the year ended December 31, 2023. The increase between periods was primarily due to higher net operating cash flows from the Hibernia, Tap Rock, and Vencer acquisitions. This increase was partially offset by a $371.3 million increase in cash paid for interest and a $411.2 million increase in changes in operating assets and liabilities primarily due to the reduction of (i) $239.6 million in production taxes payable from lower commodity pricing and (ii) $176.0 million in crude oil and natural gas revenue distributions payable primarily as a result of the full integration of the Hibernia and Tap Rock acquisitions into our systems and processes. See “ Results of Operations ” above for more information on the factors driving these changes.
Uses of Cash and Cash Equivalents
Our uses of cash and cash equivalents decreased by $1.7 billion year over year, primarily driven by the 2023 Hibernia and Tap Rock acquisitions for $3.7 billion, partially offset by $905.1 million for acquisitions in 2024 mainly related to the Vencer Acquisition. In addition, cash and cash equivalents used to pay dividends decreased by $166.5 million during the year ended December 31, 2024, as dividends declared and paid decreased from $7.60 per share in 2023 to $4.97 per share in 2024 largely attributable to a decrease in Adjusted Free Cash Flow for the preceding twelve-month period, as well as our decision to adjust the return of capital allocation beginning in the third quarter of 2024. This decision contributed, in part, to a
$106.9 million increase in common stock repurchased and retired during the year ended December 31, 2024, compared to the year ended December 31, 2023.
The above described net decrease was partially offset by $830.0 million of increased payments to our Credit Facility in 2024 in connection with our efforts to pay down debt following the draws made in late 2023 to partially fund the Vencer Acquisition. Lastly, capital expenditures for drilling and completion activities and other fixed assets increased by $572.0 million, largely attributable to a full year of operating assets acquired in the Hibernia and Tap Rock acquisitions, as well as the Vencer Acquisition completed in early 2024. During 2024, we drilled, completed, and turned to sales 114.0, 123.3, and 107.6 net operated wells, respectively, in the Permian Basin, and 75.1, 82.8, and 103.9 net operated wells, respectively, in the DJ Basin. During 2023, we drilled, completed, and turned to sales 44.3, 48.9, and 66.7 net operated wells, respectively, in the Permian Basin, and 90.6, 107.8, and 124.3 net operated wells, respectively, in the DJ Basin.
Non-GAAP Financial Measures
Reconciliation of Net Income to Adjusted EBITDAX
Adjusted EBITDAX is a supplemental non-GAAP financial measure that represents earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash and non-recurring charges. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. We present Adjusted EBITDAX because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Facility based on Adjusted EBITDAX ratios. In addition, Adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the crude oil and natural gas exploration and production industry. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because Adjusted EBITDAX excludes some, but not all items that affect net income and may vary among companies, the Adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies.
The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted EBITDAX for the periods presented (in thousands):
Year Ended December 31,
Net income
Exploration
Depreciation, depletion, and amortization
Unused commitments (1)
Transaction costs
Stock-based compensation (2)
Derivative gain, net
Derivative cash settlement gain (loss), net
Interest expense
Interest income (3)
Loss on property transactions, net
Income tax expense
Adjusted EBITDAX
(1) Included as a portion of other operating expense in the accompanying consolidated statements of operations.
(2) Included as a portion of general and administrative expense in the accompanying consolidated statements of operations.
(3) Included as a portion of other income in the accompanying consolidated statements of operations.
Reconciliation of Cash Provided by Operating Activities to Adjusted Free Cash Flow
Adjusted Free Cash Flow is a supplemental non-GAAP financial measure that is calculated as net cash provided by operating activities before changes in operating assets and liabilities and less exploration and development of crude oil and
natural gas properties, changes in working capital related to capital expenditures, and purchases of carbon credits. We believe that Adjusted Free Cash Flow provides additional information that may be useful to investors and analysts in evaluating our ability to generate cash from our existing crude oil and natural gas assets to fund future exploration and development activities and to return cash to stockholders. Adjusted Free Cash Flow is a supplemental measure of liquidity and should not be viewed as a substitute for cash flows from operations because it excludes certain required cash expenditures.
The following table presents a reconciliation of the GAAP financial measure of net cash provided by operating activities to the non-GAAP financial measure of Adjusted Free Cash Flow for the periods presented (in thousands):
Year Ended December 31,
Net cash provided by operating activities
Add back: Changes in operating assets and liabilities, net
Cash flow from operations before changes in operating assets and liabilities
Less: Cash paid for capital expenditures for drilling and completion activities and other fixed assets
Less: Changes in working capital related to capital expenditures
Capital expenditures
Less: Purchases of carbon credits and renewable energy credits
Adjusted Free Cash Flow
Reconciliation of Standardized Measure to Proved Reserves PV-10
PV-10 is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure on a pre-tax basis. PV-10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our crude oil and natural gas properties. We use this measure when assessing the potential return on investment related to our crude oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure. Neither our PV-10 measure nor the Standardized Measure purports to present the fair value of our crude oil and natural gas reserves.
The following table provides a reconciliation of the GAAP financial measure of Standardized Measure to the non-GAAP financial measure of PV-10 as of the periods presented (in millions):
As of December 31,
Standardized Measure
Present value of future income taxes discounted at 10%
Reconciliation of average sales price, after derivatives
Average sales price, after derivatives is a non-GAAP financial measure that incorporates the net effect of derivative cash receipts from or payments on commodity derivatives that are presented in our accompanying consolidated statements of cash flows, netted into the average sales price, before derivatives, the most directly comparable GAAP financial measure. We believe that the presentation of average sales price, after derivatives is a useful means to reflect the actual cash performance of our commodity derivatives for the respective periods and is useful to management and our stockholders in determining the effectiveness of our price risk management program.
The following table provides a reconciliation of the GAAP financial measure of average sales price, before derivatives to the non-GAAP financial measure of average sales prices, after derivatives for the periods presented:
Year Ended December 31,
Average crude oil sales price (per Bbl)
Effects of derivatives, net (per Bbl) (1)
Average crude oil sales price (after derivatives) (per Bbl)
Average natural gas sales price (per Mcf)
Effects of derivatives, net (per Mcf) (1)
Average natural gas sales price (after derivatives) (per Mcf)
Average NGL sales price (per Bbl)
Effects of derivatives, net (per Bbl) (1)
Average NGL sales price (after derivatives) (per Bbl)
(1) Derivatives economically hedge the price we receive for crude oil, natural gas, and NGL. For the year ended December 31, 2024, the derivative cash settlement loss for crude oil was $41.7 million and the derivative cash settlement gain for natural gas was $48.1 million. For the year ended December 31, 2023, the derivative cash settlement loss for crude oil and natural gas was $59.5 million and $8.7 million, respectively. We did not hedge the price we received for NGL during the periods presented. Refer to “ Item 8. Financial Statements and Supplementary Data - Note 9 - Derivatives ” of this Annual Report on Form 10-K for additional disclosures.
Critical Accounting Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these statements requires us to make certain assumptions, judgments, and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses, as well as the disclosure of contingent assets and liabilities and commitments as of the date of our consolidated financial statements. We evaluate our estimates and assumptions on an ongoing basis. We analyze and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. We believe the following discussions of critical accounting estimates address all important accounting areas where the nature of accounting estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change. Our significant accounting policies are described in “ Item 8. Financial Statements and Supplementary Data - Note 1 - Summary of Significant Accounting Policies .”
Crude Oil and Natural Gas Properties
Proved Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Under this method, the costs of development wells are capitalized to proved properties whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities are depleted using the units-of-production method based on estimated proved developed reserves. Proved leasehold costs are also depleted; however, the units-of-production method is based on estimated total proved reserves.
We assess proved properties for impairment whenever events or circumstances indicate that their carrying value may not be recoverable. If carrying values exceed undiscounted future net cash flows, impairment is measured and recorded at fair value. Because there usually is a lack of quoted market prices for proved properties, we estimate the fair value using valuation techniques that convert estimated future net cash flows to a single discounted amount. Significant inputs and assumptions to this estimation include, but are not limited to, reserves volumes, future operating and development costs, future commodity prices, inclusive of applicable differentials, and a market-based weighted average cost of capital rate. The expected future cash flows used for impairment reviews include future sales volumes associated with proved developed reserves and risk-adjusted proved undeveloped reserves.
Unproved Properties. Unproved properties consist of the costs to acquire undeveloped leases and are not subject to depletion until they are transferred to proved properties. Leasehold costs are transferred to proved properties on an ongoing basis as the properties to which they relate are evaluated and proved reserves established. Unproved properties are routinely evaluated for impairment. On a quarterly basis, management assesses undeveloped leasehold costs for impairment by considering, among other things, remaining lease terms, future drilling plans and capital availability to execute such plans, commodity price outlooks, recent operational results, reservoir performance and geology, and estimated acreage value based on prices received for similar, recent acreage transactions by us or other market participants. If circumstances dictate that the carrying value of unproved properties may not be recoverable, we perform a recoverability test. If carrying values exceed the undiscounted future net cash flows associated with probable and possible reserves, impairment is measured and recorded at fair value. Because there usually is a lack of quoted market prices for unproved properties, we estimate the fair value using valuation techniques that convert estimated future net cash flows to a single discounted amount. Significant inputs and assumptions to this estimation include, but are not limited to, reserves volumes, future operating and development costs, future commodity prices, inclusive of applicable differentials, and a market-based weighted average cost of capital rate. The expected future cash flows used for impairment reviews include future sales volumes associated with probable and possible reserves. Changes in our assumptions of the estimated nonproductive portion of our undeveloped leases could result in additional impairment expense.
Crude Oil and Natural Gas Reserves. The successful efforts method of accounting outlined above inherently relies on the estimation of proved crude oil and natural gas reserves. Reserve quantities and the related estimates of future net cash flows are critical inputs in our calculation of units-of-production depletion and our evaluation of proved and unproved properties for impairment. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring the evaluation of available geological, geophysical, engineering and economic data to estimate underground accumulations of crude oil and natural gas that cannot be precisely measured. Consequently, we engage an independent third-party reserve engineering firm, Ryder Scott, to audit our estimates of crude oil and natural gas reserves. Significant inputs and engineering assumptions used in developing the estimates of proved crude oil and natural gas reserves include reserves volumes, future operating and development costs, historical commodity prices, and our ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking.
The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. If the estimates of proved reserve quantities decline, the rate at which we record depletion expense will increase, which would reduce future net income. Changes in depletion rate calculations caused by changes in reserve quantities are made prospectively. In addition, a decline in reserve estimates may impact the outcome of our assessment of proved and unproved properties for impairment. Impairments are recorded in the period in which they are identified.
We cannot predict future commodity prices. However, we performed a sensitivity analysis on our proved reserve estimates as of December 31, 2024, to present a decrease of approximately 10% in crude oil and natural gas price (and holding all other factors constant), as the value of crude oil and natural gas influences the value of our proved reserves most significantly. As a result, our proved reserve quantities would decrease by 29.7 MMBoe or 4%. The reserve decrease would have increased our DD&A rate by $0.64 per Boe and decreased our pre-tax income by $81.0 million for the year ended December 31, 2024. This estimated impact is based on available data as of December 31, 2024, and future events could require different adjustments to our DD&A rate. There were no impairment charges recognized related to our proved and unproved properties during the years ended December 31, 2024 or 2023. For more information regarding reserve estimations, including additional sensitives and descriptions over historical reserve revisions, see “ Part I - Item 1. - Business ”, “ Part I - Item 2. Properties ”, and “ Item 8. Financial Statements and Supplementary Data - Note 16 - Disclosures About Oil and Gas Producing Activities ” included elsewhere in this report.
Business Combinations
As part of our business strategy, we regularly pursue the acquisition of crude oil and natural gas properties. We utilize the acquisition method to account for acquisitions of businesses. Pursuant to this method, we allocate the cost of the acquisition, or purchase price, to assets acquired and liabilities assumed based on fair values as of the acquisition date. Any excess of the purchase price over the fair value amounts assigned to assets and liabilities is recorded as goodwill. Any deficiency of the purchase price over the estimated fair values of the net assets acquired is recorded as bargain purchase gain in the statements of operations.
During 2024, we accounted for one business combination under the acquisition method of accounting, the Vencer Acquisition. In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant of these assumptions relate to the estimated fair values assigned to proved and unproved properties, which resulted in $2.1 billion for the Vencer Acquisition. Because sufficient market data may not be available regarding the fair values of our acquired proved and unproved oil and gas properties, we engage a third-party valuation expert to assist in preparing the fair value estimates. We utilize a discounted cash flow approach, based on market participant assumptions. Significant judgments and assumptions are inherent in these estimates and include, among other things, reserve quantities and classification, pace of drilling plans, future commodity prices, future development and lease operating costs, reserve adjustment factors, and discount rates using a market-based weighted average cost of capital determined at the time of the acquisition. When estimating the fair value of unproved properties, reserve adjustment factors are applied to probable and possible reserves. The purchase price consideration for the Vencer of $2.0 billion was allocated to the assets acquired and liabilities assumed based upon their estimated acquisition date fair values and resulted in no goodwill or bargain purchase gain.
Estimated fair values ascribed to assets acquired can have a significant impact on future results of operations presented in our consolidated financial statements. For example, a higher fair value ascribed to proved properties results in higher DD&A expense, which results in lower net income. As discussed above, estimated fair values assigned to proved and unproved properties are dependent on estimates of reserve quantities, future commodity prices, as well as development and operating costs. In the event that reserve quantities or future commodity prices are lower than those used as inputs to determine estimates of acquisition-date fair values, the likelihood increases that certain costs may be determined to not be recoverable and increases the likelihood of future impairment charges.
In addition, we record deferred taxes for any differences between the assigned fair values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
Effects of Inflation and Pricing
Inflation in the United States averaged 3.0% in 2024, 4.1% in 2023, and 8.0% in 2022. While we experience cost inflation on labor, power, and other key costs in our operations and development program, we do not believe it had a material impact on our results of operations for the periods ended December 31, 2024, 2023, or 2022.
We tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing crude oil and natural gas prices increase drilling activity in our areas of operations. Material changes in prices also impact the current revenue stream, estimates of future reserves, borrowing base calculations, depletion expense, impairment assessments of crude oil and natural gas properties, asset retirement obligations, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of crude oil and natural gas companies and the rate of return associated with the wells they develop and can hinder their ability to raise capital, borrow money, and retain personnel. With increased commodity prices and drilling activity, there have been increased costs associated with parts, materials, labor and other necessary drilling and completions related resources, including contracts for drilling and workover rigs and oilfield service companies.
